committee 11v/docs_api_gaslift... · web viewuse side-pocket mandrels with a pressure rating...

5.6 Recommended Practices for Very Deep Gas-Lift

These recommended practices are specific and/or unique for very deep gas-lift operations.

o Authors: To be determined

These recommended practices are unique to very deep gas-lift operations, where very deep is defined as more than 20,000 feet true vertical beneath the casing-head flange. Please make certain that the following unique items are addressed in this Section 5.6: Specify the minimum design validation and functional evaluation requirements for gas-

lift equipment. System elements and design considerations. Pre-installation requirements. Start-up considerations. Operational and maintenance considerations. Intervention considerations Root cause of failure analysis. Data collection requirements. Reference standards.

Note. Making modifications to sub-sea gas lift installations is usually very expensive. This includes, for example, the replacement of subsea flow meters or chokes, or changing-out gas lift valves. It is therefore paramount to select the best equipment available for such applications, and to design for robustness. In many cases it is possible to build in redundancy at little extra cost. This provides a fall-back option in case of failing hardware where replacement is not economic.

Note. Highlight items in bold red that need to be defined in Terms and Definitions.

Note: The following sub-sections are taken from API RP 19G13, Section 5.1, Common System Elements. Under each sub-section, the text is copied from Section 5.1 and is shown in red. This is to make it easy to see the text from Section 5.1 without needing to open an extra document. The goal here, under each sub-section, is to add information that is unique to sub-sea gas-lift, if any additional items are needed. It information needs to be added to this Section 5.6 that doesn’t fit under one of the existing sub-section headings, additional sub-sections may be added.

When this Section 5.6 has been drafted, the “red” text below will be removed so all this is left will be each section heading and new items that have been added. If it is necessary to make any changes to the “red” text, send a note to Wayne Mabry or Cleon Dunham. Do not change it here. The sub-section numbers shown below are identical to the same sub-section numbers in Section 5.1. When this section is completed, the sub-section numbers will be changed to be part of Section 5.6.

5.1.1 Common System Elements

5.1.1.1 Recommended Practices for Material Selection (e.g. high pressure, high temperature, H2S, CO2)

a. Design all pressure containing equipment for the life of the well, specificallly addressing applicable codes, pressuire ratings, tri-axial stress conditons for the worst cases for maximum and minimum pressures and temperatures that may be encountered.

b. Predict worst case conditions for the occurrence of H2S, CO2, and water vapor in the lift gas, gas hydrates, asphaltines, and other

API RP 19G13 --- Section 5.6 --- Very Deep Gas—Lift

fluids introduced during the life of the well. Obtain reservoir fluid samples for PVT analysis and detailed composition. Select materials that are designed for the environments that will be experienced, especially considering the worst case of expected pressures and temperatures.

Use the recommended practices in Section 5.1 that are common to all challenging gas-lift applications. The following items, if any, are unique to very deep gas-lift wells.

5.1.1.2. Recommended Practices for Surface Equipment

a. Safety is of paramount importance in extreme gas-lift environments. Design all surface equipment for fail-safe operation. Recommended practices for verification of the designs are presented in the section on Installation.


5.1.1.2.1. Practices for Dehydration

a. Dehydrate all lift gas to at least three pounds of water vapor per million cubic feet of gas, or lower if necessary to prevent hydrate formation. This is essential to prevent any risk of corrosion or problems that may arise due to liquid accumulation or hydrate formation in the gas-lift system.

b. Minimize disruption in the dehydration process to reduce the off-specification gas that enters the gas-lift distribution system.

c.Gas pressure systems designed for single point injection may require discharge pressures ranging from 2000 psig to 6000 psig or higher. Dehydration should be done at an inter-stage pressure between 800 psig to 1200 psig to eliminate excess glycol carryover with high density gas.


5.1.1.2.2. Practices for Compression

a. Select the compressor discharge pressure with the first priority being safety. Design a discharge pressure that is as high as is safe and feasible to minimize the number or eliminate unloading gas-lift valves.

b. Use centrifugal compressors for greater capacity, lower weight and vibration, smaller foot print, and higher reliability; use reciprocating compressors for lower capacity, better rate flexibility, and insensitivity to gas molecular weight changes.


c. Provide as much redundancy for the lift gas compression system, including the compressors and prime movers, as is economically feasible. A detailed plan for start-up and/or re-start is required that addresses HSE and systems interactions.

d. Provide instrumentation and logic to continuously monitor the compression system and evaluate its performance.

e. Equip the compression facility with vibration monitoring to detect and address any installation or alignment problems.


5.1.1.2.3. Practices for Lift Gas Distribution

a. Provide redundant lift gas distribution lines to the extent that is economically feasible.

b. Right-size the distribution lines to minimize pressure drops between the compressor discharge and the gas-lift injection manifold or wellhead.

c. If there are low spots in the distribution system, provision of adequate dehydration is even more important to prevent of liquid accumulation and slugging.

d. Provide a mechanism to purge the distribution system lines of liquids, and use pig launchers/receivers on the large constant diameter pipelines from the compressor station. When pigging operations are being used, a detailed plan is required that addresses HSE and system interactions.

e. Provide instrumentation and logic to continuously monitor the distribution system and evaluate its performance.

f. Provide automated control valves, with manual back-up, to control the gas flow into the distribution system and the flow from the system to the gas-lift wells.


5.1.1.2.4. Practices for Lift Gas Injection Manifold

a. Measure the lift gas pressure, temperature, and flow rate upstream of the manifold. This can be used to double check the total rate of lift gas in the system and the rate being injected into each well.

b. Measure the lift gas flow rate to each well immediately downstream of the manifold or at the wellhead. The pressure and temperature upstream of the manifold can be used to compensate gas flow rate measurements to each well served by the manifold.


c. Provide automated flow control valves to control the gas flow from the manifold to the individual wells.

d. Provide automated shut-in valves, with manual back-up, if feasible, that can be used to provide a positive shut-off of gas flow to any particular well.


5.1.1.2.5. Practices for Lift Gas Measurement and Control

a. Implement the recommendations for measurement and control equipment that are provided in Section 5.1.d.

b. Use high quality measurement and control devices. Failures and poor performance are not acceptable.

c. Install measurement and control devices so they can be maintained and calibrated or verified without interrupting gas flow in the system.

d. Install measurement and control devices to avoid low spots where liquids can accumulate and any sharp bends where erosion may occur.

e. Equip each automated lift gas flow control valve with a position feedback sensor and implement an algorithm to calculate the lift gas flow rate based on valve Cv, valve position and differential pressure. This provides a redundant option if the lift gas flow meter fails.


5.1.1.2.6. Practices for the Wellhead

a. Install pressure measurement instruments to measure gas injection pressure directly on the casing head, downstream of any pressure restrictions or control devices.

b. Install pressure measurement instruments to measure production pressure directly on the tubing head, upstream of any pressure restrictions or control devices.

c. Minimize use of 90o elbows and reduced inside diameter (ID) valves that create potential flow restriction or erosion.


d. Install automatic control valves so the well can be positively shut-in remotely. Provide manual back-up valves, where feasible, for shut-in if the automation system fails.

e. Install automatic adjustable control valves or chokes so the well’s lift gas injection rate can be adjusted if it is not controlled at the injection manifold.

f. Install automatic adjustable production control valves or chokes so the well’s production rate can be adjusted if necessary to minimize instabilities.

g. If instability can be controlled or eliminated by injection control of lift gas, remove chokes and choke bodies from existing wellheads to minimize flow restriction.


5.1.1.2.7. Practices for Surface and Sub-Surface Annular Safety Systems

a. Perform a risk-based evaluation of containing high-pressure lift gas and consider the use of surface and sub-surface annular safety systems.

b. If an annular safety system is to be used, select materials for the valve and control line that are compatible with the downhole environment.

c. If a control line is used, the protection system must prevent damage to the line during the running operation.

d. Comply with regulatory requirements for testing procedures and frequency.

e. Comply with manufacturer’s start-up and operating procedures to avoid damaging the system. A detailed plan is required that addresses HSE and system interactions.

f.


5.1.1.2.8. Practices for the Flowlines

a. Design flow lines to minimize pressure drops between the wellhead and the production manifold, but don’t oversize the lines to avoid severe slugging that may arise in later life when the production rates of the wells may decline.

b. Provide a mechanism to clean the flow lines if paraffin or solids accumulate in them. Provide access to circulate fluids from a host


platform or FPSO for cleaning or displacement required for shutdown periods.

c. Provide automated control valves, with manual back-up, if feasible, to permit flowlines to be serviced and pressure tested.

d. Provide instrumentation and logic to continuously monitor the flow lines and evaluate their performance. As a minimum, measure the pressure entering the flowline at the wellhead and the pressure entering the production manifold.


5.1.1.2.9. Practices for the Production Manifold

a. Design the production manifold so each well can be automatically switched into each production pressure system, if there is more than one system.

b. Design the manifold so each well can be automatically switched into the well test system.

c. Provide automated control valves, with manual back-up, if feasible, to permit the wells to be automatically or manually switched.

d. Design the manifold so any valve can be isolated for maintenance without interrupting flow through the manifold.


5.1.1.2.10. Practices for Well Testing

a. Measure oil, water, and gas rates separately by using three-phase well test separators if the separators are available for the wells.

b. Measure oil and water rates with appropriate metering devices for the fluid characteristics and location. Choices include turbine, coriolis density, and multiphase meters.

c. Measure gas production rate with appropriate metering devices for surging gas flow. Choices include orifice, sonic, coriolis density, and multiphase meters.

d. Provide a process to calibrate the well test meters without disrupting flow in the production station or platform.

e. Measure and control the pressure in the test separator so it is equal to the pressure in the bulk separator. If the test separator


must be a higher pressure, apply the correct shrinkage factors to both test and bulk separator liquid rates.

f. Provide a process to clean the separator without disrupting flow in the production station or platform.

g. Automate the well test process so each well test time is suitable for the objective, for example a quick surveillance test, a test to identify problems, or a regulatory test.


5.1.1.2.11. Practices for Separation and Treating – Separator, FWKO, Heaters, Treaters, Tanks, Pumps, etc.

a. If pertinent, provide multiple production pressure systems. The gas-lift wells should normally be produced into the lowest pressure system. Flowing wells may be produced into higher pressure systems.

b. Measure oil, water, and gas rates separately by using three-phase production separators.

c. Use turbine or equivalent meters, rather than “dump” meters, to measure oil and water rates.

d. Use turbine meters, orifice meters, or equivalent to measure gas production rates.

e. Provide a process to calibrate the production meters without disrupting flow in the production station or platform.

f. Measure the pressure of the production separator and use a back pressure regulator to keep the pressure of the separator constant.

g. Provide a process to clean the separator without disrupting flow in the production station or platform.

h. Design the production equipment - free-water knockouts, heaters, treaters, tanks, pumps, etc. to maintain minimum back pressure on the production system.


5.1.1.3. Recommended Practices for Sub-Surface Equipment

a. Design all sub-surface equipment for the highest degree of safety and reliability. In most cases, the equipment must function for the life of the well as access to the wellbore for maintenance and/or replacement of


downhole equipment will, at best, be very difficult and expensive, and it may be completely unfeasible.


5.1.1.3.1. Practices for Gas-Lift Mandrels

a. Before selecting gas-lift mandrels, determine if single-point injection will be sufficient, or if unloading valves that will need multiple mandrels will be required.

b. Use side-pocket mandrels with a pressure rating compatible with the worst case pressures and temperatures at well depths that are designed to accept gas-lift valves installed by wireline or coiled tubing.

c. Order gas-lift mandrels using the API 19G1, ISO International Standard 17078-1. Use the highest Design Validation Requirement V1, the highest Product Functional Requirement F1, the highest Quality Control Requirement Q1, and the Environmental Service Requirement E1 – E4 depending on the level of service required.

d. Use mandrels with the largest pocket bore size that are compatible with the tubing selected for the well.

e. If more gas must be injected than can flow through the gas-lift valve that fits in the selected pocket bore, increase the pocket bore diameter to accommodate a larger valve, or use two or more mandrels located one above the other, one tubing joint apart.


5.1.1.3.2. Practices for Gas-Lift Valves

a. Before selecting gas-lift valves, determine if single-point injection will be sufficient, or if unloading gas-lift valves that will be required.

b. Use the largest diameter gas-lift valves that are compatible with the selected mandrels that can be installed with wireline, tractors, or coiled tubing. Avoid use of 1.0-inch or smaller valves if possible.

c. Order all gas-lift valves using API 19G2, ISO International Standard 17078-2. Use the highest Design Validation Requirements V1, the highest Product Functional Requirements F1, the highest Quality Control Requirements Q1, the Environmental Service Requirements E1 – E4 depending on the level of service required.


d. If the well’s conditions are more severe than the API/ISO design/validation conditions that were used in the original testing, then additional testing may be required. These might include: Bellow life-cycle testing at pressures consistent with actual

operating pressures. Testing at temperatures consistent with actual operating

temperatures. Additional testing at higher wellbore deviations than 45o.

e. API 19G2 specifies fresh water for erosion testing. If a more erosive fluid is to be flowed through the valve at rates higher than those qualified, additional testing may be required.

f. If more gas must be injected than can flow through the selected gas-lift valve, increase its diameter or use two or more valves located one above the other, one tubing joint apart.

g. If single-point injection will be used, use an orifice valve for the point of injection.

h. Use a venturi-type orifice instead of a square-edge orifice to ensure stability if there is little pressure margin between available supply pressure and expected casing head pressure

i. If single-point injection will be used and the well will not require gas lift initially, shear-type valves are recommended. These valves prevent annulus fluids from entering the tubing when the pressure in the tubing drops below the pressure in the annulus at the injection point. This may lead to a large vacuum above the liquid level in the annulus.

j. If unloading gas-lift valves will be required, use injection pressure operated (IPO) valves for unloading and an orifice valve for the point of injection.

k. Use back-check valves in all gas-lift valves and orifices that are designed to be leak tight and are tested with a maximum leak rate of 1.0 Ft3 of gas per day.

l. In applications where barrier-qualified gas-lift valves are required, additional testing will be required. See testing requirements in the Norwegian barrier standard WR0534.

m. Use tungsten carbide balls and seats, or other materials that have equal or grater erosion resistance, on gas-lift valves to minimize the possibility of erosion.

n. Test each gas-lift valve before installation to verify its opening pressure, closing pressure, flow coefficient, load rate, maximum stem travel, and back check integrity.



5.1.1.3.3. Practices for Surface Controlled Sub-Surface Safety Valve (SCSSV)

a. Use SCSSV’s that are API monogrammed and meet the requirements of API 14A / ISO xxx.

b. Install deep-set valves, beneath gas-lift mandrel(s).

c. Select materials for the valve and control line that are compatible with the downhole environment.

d. Select valve internal diameter to allow passage of tools.

e. The control line protection system must prevent damage to the line during the running operation.

f. Comply with regulatory requirements for testing procedures and frequency.

g. Comply with valve manufacturer’s start-up procedures to avoid damaging the valve.


5.1.1.3.4. Practices for Nipples

a. Use nipples that are API monogrammed and meet the requirements of API xxx / ISO xxx.

b. Select materials for the nipples that are compatible with the downhole environment.

c. Select nipple internal diameter to allow passage of tools.

d. Locate nipples in the well to allow maximum use functionality for isolation, landing of special tools such as wireline baskets.


5.1.1.3.5. Practices for Tubing

a. Use tubing that is API monogrammed and meet the requirements of API xxx / ISO xxx.

a. Select material for the tubing that is compatible with the downhole environment.


1. Design to withstand worst case burst and collapse pressures at downhole temperatures.

2. Design to accommodate worst case tensile and compressive loads at downhole pressures and temperatures.

3. Select tubing end connections that are compatible with the tubing selection and that meet or exceed the worst case scenarios for the downhole pressures, temperatures, and loads.

4. Size the tubing to handle the expected production rates, avoid slugging later in life, and permit use of wireline retrievable mandrels/valves.


5.1.1.3.6. Practices for Casing/Liners

a. Use casing and liners that are API monogrammed and meet the requirements of API xxx / ISO xxx.

b. Select materials for the casing and liners that are compatible with the downhole environment.

c. Design to withstand worst case combined loading conditions that include pressures, tensile loads, compressive loads, and downhole temperatures. Thoroughly explore consequences of interactions between the A and B annuli.

d. Select casing and liner end connections that are compatible with the casing/liner selection and that meet or exceed the worst case scenarios for the downhole pressures, temperatures, and loads.

e. Size casing to allow design gas flow down the annulus with minimum restrictions and to insure space for all hardware installed with the tubing.


5.1.1.3.7. Practices for Packers

a. Use packers that are API monogrammed and meet the requirements of API xxx / ISO xxx.

b. Select material for the packers that are compatible with the downhole environment.


c. Design to withstand worst case combined loading conditions that include pressures, tensile loads, compressive loads, and downhole temperatures.

d. Choose permanent or retrievable packers that minimize risk of slipping or becoming unseated at expected downhole pressure and temperature conditions.

e. Choose the packer profile to accommodate passage of tools and measurement equipment that can pass through the tubing.

f. Choose a completion fluid in the annulus that minimises the risk of casing corrosion near the point of injection. This is important in particular where the lift gas contains carbon dioxide. Base oil is often the best choice.


5.1.1.3.8. Practices for Chemical Injection

a. Use a capillary tubing string, mounted to the external of the tubing, to convey chemical to a downhole chemical injection valve.

b. Injection chemical fluids must meet NAS-6 or better cleanliness requirements. They must be selected and tested at worst case downhole pressures and temperatures to insure no precipitation of solids or changes in properties that would render the system inoperable.

c. Select the chemical injection valve opening pressure to maintain the full column of fluid in the capillary injection string to prevent formation of vapor in the control line.

d. Order all chemical injection valves using API 19G2, ISO International Standard 17078-2. Use the highest Design Validation Requirements V1, the highest Product Functional Requirements F1, the highest Quality Control Requirements Q1, the Environmental Service Requirements E1 – E4 depending on the level of service required.

e. If the well’s conditions are more severe than the API/ISO design/validation conditions that were used in the original testing, then additional testing may be required. These might include: Life-cycle testing at pressures consistent with actual operating

pressures. Testing at temperatures consistent with actual operating

temperatures. Additional testing at higher wellbore deviations than 45o.

f. Use back-check valves in all chemical injection valves that are designed to be leak tight and are tested with a maximum leak rate of 1.0 Ft3 of gas per day.


g. In applications where barrier-qualified chemical injection valves are required, additional testing will be required. See testing requirements in the Norwegian barrier standard WR0534.


5.1.1.3.9. Practices for Flow assurance

a. Flow assurance issues for challenging gas-lift applications are essentially the same as for all other gas lift systems. However, in many cases surrounding temperatures may be colder (subsea) or system pressures may be higher (deep wells) than typical. Analysis must include the expected range of steady state operation conditions over the life of the field as well as transient conditions such as start-up and shut down.


5.1.1.3.10. Practices for Hydrate Management

a. A hydrate management plan should be developed to prevent produced fluids from potentially forming hydrate blockages in the line during normal operations, shut downs, and start-ups. The plan may require use of thermal management (insulation, active heating, turndown limits), composition modifications (dehydration), chemical inhibitors (glycol, methanol, anti-agglomerants, kinetic hydrate inhibitors) and pressure management (blow down).

b. Gas-lift gas should be dehydrated to a dew point less than the coldest temperature expected in the distribution system. Analysis should include potential Joule Thomson cooling at chokes and cooling to ambient conditions during unplanned shut in events.

c. Consideration should be given to remediation methods if a hydrate blockage does occur. Typically this involves providing a means of depressurization on both sides of a potential blockage location.


5.1.1.3.11. Practices for Solids deposition (Asphaltenes, Scale, Sand, Paraffin, Salt)

a. Most solids, such as wax, scale, and sand, are no worse for gas lifted wells than they would be for a naturally flowing well.


b. Fluids should be screened for potential asphaltene precipitation due to mixing with the gas-lift gas stream. The addition of a gas lift stream may shift the asphaltene solubility in the fluid.


5.1.1.3.12. Practices for Erosion

a. Recommendations within API 14E for maximum mixture velocity to avoid pipeline erosion are frequently used as a screening tool. If the API 14E methodology indicates a potential problem or if solids production is expected, proprietary tools are available which provide a better estimate of potential erosion issues. If erosion is an issue, fluid velocity must be decreased (larger diameter, lower rate, higher pressure) or premium materials used (CRA clad pipe).


5.1.1.3.13. Practices for Emulsions

a. Testing should be conducted when possible to evaluate the potential for emulsion formation, the resulting emulsion viscosity, and the ease of breaking the emulsion in the separator. If needed, emulsion breaking chemicals should be injected as early into the flow stream as practical.


5.1.1.3.14. Practices for Completion Considerations

Pressure differentials when place gas in the annulus.

1. The


5.1.2. Design of Gas-Lift Installation

The recommended practices for designing gas-lift systems for challenging applications go well beyond the practices recommended for normal gas-lift


applications. Because of the extreme environments encountered in these applications, systems must be designed for very high reliability.


5.1.2.1. Recommended Practices for Depth of injection

a. Selection of the depth of injection is a critical factor in gas-lift design for challenging applications.

b. Prepare production system equipment performance models to determine the feasible compressor size and discharge pressure.

c. Select the depth of injection that provides the best balance between required injection pressure and desired wellbore pressure drawdown.


5.2.2.22 Practices for Location of Injection

a. In some cases, the recommended location for injection may not be in the wellbore. Section 5.2.a presents Recommended Practices for Sub-Sea Gas-Lift where the preferred injection location may be at the base of the riser from the sea floor to the platform, at the wellhead which may be at the end of a long flowline from the wellhead to the base of the riser, or downhole in the wellbore.

b. Use a transient multiphase simulator (see API RP 19G11) to evaluate the location for injection, and if injection is started at the riser base or the wellhead, the correct time to switch from riser or wellhead injection to downhole injection.

c. Evaluate the costs, risks, and benefits of high injection pressure and single point injection vs. lower injection pressure and use unloading gas-lift valves to reach the desired depth of injection.


5.2.2.23 Practices for Reservoir Performance Over Time – Life of Well – Pressure, Inflow, Water Cut, GOR

a. The following factors must be known to the highest degree of accuracy possible. Both the current values and the expect values over time are required. Reservoir pressure


Reservoir fluid properties Water cut Gas oil ratio Reservoir inflow performance

b. Prepare a reservoir model and perform reservoir studies to predict these values over time as production, depletion, and reservoir pressure maintenance occur.


5.2.2.24 Recommended Practices for System design

a. The following system components must be designed for the expected (predicted) life of the field.

b. If they are over-designed initially, it may be impossible to maintain flow stability later in the well’s life.

c. If they are under-designed initially, production may be deferred, damaging the economic performance of the well.


5.1.2.4.1 Practices for Tubing Size

a. Select tubing size that will accommodate initial natural flow at acceptable economic rates but can support continuous gas-lift when the reservoir pressure declines or the well starts producing water.

b. Never use smaller than 2.5-inch tubing.

c. Only use larger than 4.5-inch tubing if it is justification to produce expected rates. Be aware that large tubing may result in slugging later in life if the production rate is reduced.


5.1.2.4.2 Practices for Casing Size

a. Select the production casing size after the tubing size has been selected. Select mandrels that use 1 ½” or 1 ¾” valves with the selected tubing size. Do not select the casing size first and then have to use tubing that can fit in the casing.


b. Select the production casing size, and/or liner, large enough to comfortably accommodate the desired tubing and mandrel size.

c. Select the production casing size, and/or liner, large enough to allow gas injection with minimum gas pressure drop in the annulus.


5.1.2.4.3 Practices for Gas Injection System Pressure

a. The lift gas injection pressure should be a minimum of 100 psig above the pressure needed to unload to the desired depth of lift gas injection.

b. The highest pressure that can be safely and feasibly accommodated is based on evaluation of: Surface compression system Lift gas distribution system Casing burst pressure rating Tubing collapse pressure rating Gas-lift mandrel pressure rating Gas-lift valve pressure rating

c. The pressure must be held constant at the design value. This is discussed further in Section 5.1.d on operation.

d. There should be no attempt to control the pressure to different values during unloading or normal operation. The rate is controlled, not the pressure.

e. However, the injection system pressure must be continuously monitored and the injection rate adjusted, if necessary, to maintain stable injection pressure.


5.1.2.4.4 Practices for Injection Rates

a. The lift gas injection system must be able to sustain the design injection rate in the event of a partial outage in the compression system.

b. The injection rate must be high enough to maintain stable flow in the tubing under all expected production conditions.

c. There must a reliable method to control the lift gas injection rate into each well.


d. If pressure in the lift gas injection system deviates above or below the desired value, the injection rates into the wells must be adjusted to maintain stable injection system pressure.


5.2.2.25 Recommended Practices for Mandrel Placement

a. Recommended practices for mandrel depth(s) were covered above.

b. Additional recommended practices are presented here.


5.1.2.5.1 Practices for Spacing, Bracketing

a. If single-point injection is being used, place the gas-lift mandrel a minimum of 100 vertical feet above the theoretical unloading depth to assure that the well can be unloaded.

b. If using unloading gas-lift valves, vertically space the mandrels in the top half of the well close enough together that the well can be unloaded if the reservoir pressure and/or reservoir inflow performance is higher than anticipated.

c. In the bottom half of the well, space the mandrels an even distance apart so the well can lift as deep as possible if the reservoir pressure declines or the inflow performance is not as good as expected. This process is referred to as bracketing.


5.1.2.5.2 Practices for Mandrel Size

a. Use gas-lift mandrels that can accommodate 1.5-inch or 1.75-inch gas-lift valves and/or orifices.



5.2.2.26 Recommended Practices for Gas-Lift Valves

a. Recommended practices for selecting gas-lift valves were given above.

b. These recommended practices are for sizing the valves and their associated equipment.


5.1.2.6.1 Recommended Practices for Type (IPO, PPO, Pilot), Orifice, Barrier or Non-Barrier Check Systems

a. Use only injection pressure operated (IPO) gas-lift valves. Do not consider production pressure operated (PPO) or pilot gas-lift valves.

b. Use an orifice in the gas-lift mandrel at the expected operating depth.

c. Use barrier-type back check valves on all gas-lift valves and orifices. This is to provide maximum pressure integrity for the casing annulus.


5.1.2.6.2 Practices for Port Size

a. Select the port size for the operating gas-lift valve or orifice that is large enough to accommodate the desired lift gas injection rate with a pressure drop of 150 psi to 200 psi.

b. Do not select a too-large port size as this may cause instability in the tubing.


5.1.2.6.3 Practices for Chokes

a. If using standard IPO unloading valves, consider installing chokes downstream of the ports in unloading gas-lift valves.

b. The chokes will: Avoid throttling of the unloading valves Allow more gas to be injected since the valves will be held fully open

during unloading Reduce the potential for damage to the valve port and ball since the

larger pressure drop will occur across the choke.


c. Design the choke size to pass the desired rate of lift gas during unloading.


5.1.2.6.4 Practices for Orifices

a. Consider selection of orifices and/or valve ports that can achieve critical flow at lower differential pressures than standard square-edged orifices.


5.1.3 Installation

Recommended practices for gas-lift system installation are not covered in detail in the first twelve gas-lift recommended practice documents. However, due to the importance of assuring success of the gas-lift systems in these applications, pertinent recommended practices are presented here.


5.1.3.1 Recommended Practices for Factory Acceptance Testing (FAT)

a. Test all pressure containing equipment components in the factory before they are shipped to the well site.

b. Test using applicable ISO, ANSI/ASME, ASTM, and/or other testing criteria.

c. Document all test results.


5.1.3.1.1 Practices for Barrier Tests

a. Test all pressure barriers to assure they are leak tight or adhere to specified permissible leak rates. This pertains to all valves, check valves, and back-check valves.



5.1.3.2 Recommended Practices for System Integration Testing (SIT)

a. Test all system components as they are integrated together but before they are installed to assure they withstand required pressures and are leak tight.


5.1.3.3 Recommended Practices for Post-Installation Pressure Integrity Testing

a. Test the casing, tubing, packer(s), wellhead, injection lines, flowlines, manifolds, and all other pressure containing equipment after they are installed but before they are placed in operation.


5.1.3.4 Recommended Practices for Pre-Start-up Operations

a. Circulate fluid through surface piping to remove solids and construction debris.

b. Install strainers or cone screens at flanges upstream of meters and control equipment to remove solids or construction debris that remain in the piping after purge cleaning.


5.1.4 Operation

Challenging gas lift applications require extreme care to assure the systems are operated properly and safely at all times.


5.1.4.1 Recommended Practices for Unloading


a. The gas injection pathway, including the lift gas distribution lines, the gas-lilt manifold, and the casing annulus must be cleared of liquids before gas-lift can commence.


5.1.4.1.1 Practices for Unloading Process

a. Unload components in the gas injection pathway sequentially, starting at the point closest to the gas compressor(s) and moving toward the well. Platform wells can have pig launchers/receivers or knockout vessels to aid liquid unloading, but subsea wells must have bypass valves at the wellhead to circulate liquids to the host. Liquid mixtures must be analysed to prevent freezing at the coldest potential temperature during hydrostatic testing and prior to unloading.

b. Purge lift gas distribution lines to remove liquids from the lines, using pig launchers/receivers as the best practice, but knockout vessels if pigs are not installed. Subsea gas lines of large diameter must have weight-coating (included during installation) before removing liquids from them.

c. Remove liquids from the lift gas injection manifold.

d. Remove liquids from any lift gas injection risers.

e. Remove liquids from any injection line from the riser base to the wellhead.

f. Circulate completion fluid out of the casing annulus and displace it with a lighter fluid such as diesel, if permitted (well control issues) during rig installation of equipment.

g. Displace liquid through unloading gas-lift valves at a maximum flow rate through the valves of 1.0 bbl/minute to avoid the possibility of erosion of the valve’s seat and ball.

h. Monitor the lift gas injection rate and pressure, and the production pressure during the unloading process to assure the well has been unloaded to the desired operating depth.

i. Follow unloading recommended practices in API RP 19G5.

j. Make sure that the temperature downstream of the gas lift choke does not drop below the dew point of the gas to prevent formation of hydrates. If a temperature gauge is not available, it may be required to predict the temperature with a model to calculate Joule Thomson cooling

k. Make sure that the temperature downstream of the gas lift choke does not drop below the minimum temperature allowed for the pipe work and


wellhead materials along the path to the annulus. This could cause damage due to brittleness.


5.1.4.1.2 Practices for Starting Gas-Lift

a. Gas-lift gas is used to unload the water from the piping and casing annulus, however nitrogen or other high pressure gas stream can serve the same function. Unloading should start at 30% of final design gas injection rate, implementing the pressure build-up and water rate through unloading valve guidelines. After unloading to a deep point, optimizing of lift gas rate can be conducted.

b. Assure that the well is being fully monitored as discussed below.

c. Optimize production versus gas lift rate by starting at 80% of the target lift gas injection rate and gradually building up to the full injection rate in increments of 5% of the initial target injection rate.

d. Test the well at each incremental rate to evaluate and select the optimum operating condition.


5.1.4.1.3 Practices for Kicking-Off Wells after Shut-In Period

a. A gas-lift well usually can be restarted at its optimal lift gas injection rate after a period of idle time.

b. However, if the bottom-hole pressure is relatively high, the shut-in fluid level in the tubing may stand well above the operating gas-lift valve. This may require a mini-unloading process to restart gas-lift.

c. Until certain that the well can be kicked off by restarting gas-lift injection at the normal rate, use the same process as recommended for initial start-up of starting at 50% of the normal injection rate and gradually building up to the normal rate.

d. Closely monitor the lift gas injection rate and pressure, and the production pressure, to assure the well returns to the desired operating depth.



5.1.4.1.4 Practices for Enhanced Production Because Well not Flowing at Full Potential

a. Gas-lift can be initiated while a well is still naturally flowing if gas-lift can be used to increase the production rate.

b. Gas lift is most often initiated when a well will stop flowing or has been shut down for some operational reason. If the well is restarted on gas-lift and it will flow, gas-lift is optional.

c. The implementation criterion is an economic analysis of natural flow versus gas-lifting the well, with the number of wells required to attain field-wide target rate for each case influencing the choice.

d. The preferred practice is continue to use gas-lift based on the economic criteria and not operate the well on a “sometimes on, sometimes off” basis.


5.1.4.1.5 Practices for System Stability

a. A well may be completed with large tubing to permit large initial flow rates. As the flow rate decreases due to lower bottom-hole pressure or reduced inflow performance, the flow in the tubing may become unstable, which requires additional lift gas.

b. Reduce the size of the tubing by installing a smaller tubing string, or installing an insert string. However, in many challenging gas lift wells, this may not be feasible.

c. An unstable naturally flowing well should have gas-lift implemented. The combination of the increased production rate and the added volume of gas that must be produced up the tubing may stabilize the production.


5.1.4.1.6 Practices for Well not Producing

a. A gas lift well that will not start flowing after a period of idle time requires lift gas adjustment as described above.

b. Analysis to determine why a well is not producing requires evaluation of these characteristics: low bottom-hole pressure, poor inflow performance, increased water cut, reduced gas-oil ratio, sand influx, solid deposition (paraffin, asphalt, scale), or increasing skin damage.


c. Gas lift can restore production when low bottom-hole pressure and/or increase water cut is the problem.

d. Stimulation treatment or wellbore/flowline cleaning is the solution to the other problems, then gas lift can be evaluated as a method to further increase production.


5.1.4.2 Practices for Monitoring

a. Have a plan for how each piece of information will be used in the control and surveillance strategy.

b. Don’t over-instrument, but install sufficient instrumentation to fully monitor and evaluate the well and gas-lift system performance.

c. Obtain highest quality measuring devices, instruments, and meters.

d. When possible, install devices, instruments, and meters so they can be replaced if they fail.

e. Install the devices so that if they do fail, they will not interfere with the normal operation of the well.

f. Wherever possible, have a method to estimate or infer the value of each measured variable, if an instrument fails or loses calibration.


5.1.4.2.1 Practices for Bottom-Hole Pressure

a. Install a downhole pressure measurement system to measure wellbore inflow pressure.

b. Install redundant systems so measurements can continue if one instrument fails.

c. Install the pressure measurement system below any pressure drop device so when the flow is stopped, the system can measure the reservoir pressure build-up, and if the well is down long enough, the static reservoir pressure.

d. Include a memory capability in the pressure instrument so pressures can be measured on a frequency of one data point per second immediately after a well stops or re-starts producing. This is necessary because it won’t be possible to transmit data to the surface at this frequency.


e. Provide a method to transmit individual pressure measurements to the surface, and to transmit a buffer of pressure measurements that are collected after a shut-down or re-start.

f. Use bottom-hole pressure during a shut-in to conduct a pressure build-up analysis and determine the static bottom-hole pressure.

g. Use bottom-hole pressure during normal operations, along with the static bottom-hole pressure and the production rate, to determine and track inflow performance.

h. Use the bottom-hole pressure to calibrate the calculated bottom-hole pressure from a multiphase flow nodal analysis computer program. Once the program is calibrated, it can be used to estimate the bottom-hole pressure even if the instrument fails or loses calibration.

i. Use the flowing bottom-hole pressure to adjust lift gas rate to maintain the desired downhole pressure. Gather bottom-hole pressure from all wells to evaluate the performance of the gas-lift system.


5.1.4.2.2 Practices for Bottom-Hole Temperature

a. Include a bottom-hole temperature measurement device with the bottom-hole pressure measurement device.

b. Use it to determine the static reservoir temperature when the well is shut-in.

c. Use it to determine the flowing bottom-hole temperature when the well is producing.

d. Use it to calibrate the calculated bottom-hole temperature when a temperature traverse program is used. Once the program is calibrated, it can be used to estimate the bottom-hole temperature even if the instrument fails or loses calibration

e. Use this information to evaluate increases in water fraction (temperature increases) and increases in gas coning (temperature reduces). Data from all wells can aid in evaluating the performance of the gas-lift system.


5.1.4.2.3 Practices for Distributed Temperature


a. Use a fiber-optic distributed temperature system to measure the temperature throughout the production tubing. This can be used to determine the point(s) of gas entry into the tubing if more than one unloading gas-lift valve is being used.

b. The distributed temperature system can also be used to detect a tubing leak. Lift gas will be entering the tubing through the leak and there will be cooling at that point.


5.1.4.2.4 Practices for Injection Pressure

a. Measure the lift gas injection pressure on the wellhead at the casing annulus, downstream of any pressure drop devices such as chokes or control valves.

b. Use a pressure measurement device that is accurate to +/- 5 psig and has a resolution of +/- 0.5 psig.

c. Use a device that has a maximum pressure range of at least 100 psig above the maximum lift gas injection pressure.

d. Use a “smart” instrument that can inform the SCADA system if it has measurement problems or loses calibration.

e. Use a device that is not affected by hydrate formation.

f. Read the value of the injection pressure once per second. This may be averaged by the SCADA system to one value per 30 seconds or per minute.


5.1.4.2.5 Practices for Injection Temperature

a. Measure the lift gas injection temperature on the wellhead at the casing annulus, downstream of any pressure drop devices such as chokes or control valves.

b. Use a temperature measurement device that is accurate to +/- 5 oF and has a resolution of +/- 0.5 oF.

c. Use a device that has a maximum temperature range of at least 100 OF above the maximum lift gas injection temperature.



e. Use a device that is not affected by hydrate formation.

f. Read the value of the injection temperature once per second. This may be averaged by the SCADA system to one value per 30 seconds or per minute.


5.1.4.2.6 Practices for Injection Rate

a. Measure the lift gas injection rate at the most convenient and secure location. This may be on the lift gas injection manifold or at the wellhead.

b. Use a gas flow rate measurement device that is accurate to +/- 5 thousand SCF/Day and has a resolution of +/- 0.5 thousand SCF/Day.

c. Use an orifice meter, sonic meter, or other metering device not affected by surging or non-stable gas flow. Robustness is more important than absolute accuracy.

d. Use a meter that has a maximum flow rate reading of at least 10% higher than the highest anticipated lift gas injection rate.

e. Use a “smart” instrument that can inform the SCADA system if it has measurement problems or loses calibration.

f. Use a device that is not affected by hydrate formation. This requires the selection of a device without areas where free water can accumulate. Where a differential pressure transmitter is used, the impulse lines to the transmitter should be self-draining.

g. Read the value of the injection rate once per second. This may be averaged by the SCADA system to one value per 30 seconds or per minute.


5.1.4.2.7 Practices for Production Pressure

a. Measure the production pressure on the wellhead, upstream of any pressure drop devices such as chokes or control valves.


c. Use a device that has a maximum pressure range of at least 100 psig above the maximum production pressure.



e. Use a device that is not affected by problems with hydrate, paraffin, or scale formation.

f. Read the value of the production pressure once per second. This may be averaged by the SCADA system to one value per 30 seconds or per minute.


5.1.4.2.8 Practices for Production Temperature

a. Measure the production temperature on the wellhead, upstream of any pressure drop devices such as chokes or control valves.

b. Use a temperature measurement device that is accurate to +/- 5 oF and has a resolution of +/- 0.5 oF.

c. Use a device that has a maximum temperature range of at least 100 OF above the maximum production temperatures.


e. Use a device that is not affected by problems with hydrate, paraffin, or scale formation.

f. Read the value of the production temperature once per second. This may be averaged by the SCADA system to one value per 30 seconds or per minute.


5.1.4.2.9 Practices for Production Rate Measurement or Method to Estimate

1. Continuously measure the oil, water, and gas production rate for each gas-lift well, if feasible.

2. Use a multi-phase meter to measure all three phases.

3. Optionally, measure the combined flow rate of several wells at the location closest to the wells, either a production manifold or a host separator at the surface.


4. If the combined production rate must be measured, estimate the production rates of each well by shutting one well of the group and testing the combined flow of the remaining wells. This testing by difference provides an estimate that can be used to allocate the measured rates (volumes) back to each individual well.

5. Use of continuous measurement may eliminate the need for well test separators. However, if well testing is required, use an automatic well test system to permit conducting a full test on each well at least once per week, and an estimate of each well’s production at least once per day.


5.1.4.2.10 Practices for Chemical injection

a. Measure the rate of chemical injection into the well for each chemical that it being injected.

b. Measure the injection rate(s) once per second. This may be averaged by the SCADA system to one value per 30 seconds or per minute.

c. Measure the volume of chemical stored and ready for injection to determine if the volume needs to be replenished.

d. Monitor the status of the chemical injection pump(s) to assure they are functioning properly.


5.1.4.2.11 Practices for Casing Annulus Pressure – All Annuli

a. Measure the casing annulus pressures (all annuli) on the wellhead.


c. Use a device that has a maximum pressure range of at least 100 psig above the maximum lift gas injection pressure.


e. Read the value of the injection pressure once per second. This may be averaged by the SCADA system to one value per 30 seconds or per minute.

f. Develop data for casing collapse pressure and compare to pressure on annuli. Develop procedures to relieve pressure if necessary.



5.1.4.2.12 Practices for Pressure Surveys

a. Pressure/temperature surveys in the wells associated with challenging gas-lift applications will be very expensive and risky and are likely not justified.

b. If surveys must be run, closely follow the recommended practices in API RP 11V5, Gas-Lift Operations.

c. Considering the high costs of pressure/temperature surveys it is recommended to equip these wells with downhole pressure and temperature gauges.


5.1.4.3 Recommended Practices for Control

a. Have a plan for how each variable to be controlled will be controlled.

b. Obtain highest quality control devices.

c. When possible, install control devices so they can be replaced if they fail.

d. Install the devices so that if they do fail, they will not interfere with the normal operation of the well.

e. Wherever possible, have a back-up control strategy so if one control device does fail, the system can still be safely operated.


5.1.4.3.1 Practices for System Injection Pressure (Indirect Control)

a. Control gas-lift system pressure by controlling the compressor plant discharge pressure or by sending extra gas to the sales system.

b. Provide a pressure relief system so if the pressure is too high, gas can be relieved to sales to avoid over pressure in the lift gas distribution system.

c. Do not use pressure controllers or regulators on the lift gas distribution system.


d. Control the system pressure indirectly by keeping the total lift gas injection rate into the wells served by the system in balance with the supply of lift gas into the system.

e. Use optimization techniques to increase the lift gas injection into capable wells which will reduce the pressure to the desired value.

f. Use optimization techniques to decrease the lift gas injection into one or more of the wells to increase the pressure to the desired value.


5.1.4.3.2 Practices for Rate of Gas Injection

a. Control the rate of gas injection into each gas-lift well at the most convenient location, either at the lift gas injection manifold or at the wellhead of each gas-lift well.

b. Control the lift gas injection rate to the required value depending on the gas-lift operation: unloading, kick-off, or normal operation.

c. Make any control changes gradually to not upset the system except when necessary to stop injection to prevent gas loss due to a leak or when injection in a well must be stopped for safety or environmental protection reasons.

d. When controlling lift gas injection, follow the recommended practices in API RP 11V5 and API RP 19G12.

e. Use control logic to address these three objectives, in this order: (a) keep the injection point as deep as possible given the well’s conditions, (b) keep the injection rate stable, and (c) keep the rate as close to the optimum value as possible.


5.1.4.3.3 Practices for Rate of Chemical Injection

a. Control the rate of chemical injection to the value(s) defined by the process(es) that need chemical: corrosion prevention, emulsion prevention, scale deposition prevention, paraffin deposition prevention, or hydrate prevention.



5.1.4.3.4 Practices for Back Pressure at Wellhead

a. Reduce the wellhead back pressure to the minimum value needed to allow the produced fluids to flow from the wellhead to the production station.

b. Sub-sea wells require high pressure, since flow from the wellhead may need to go through a long flowline and up a long (high) riser.

c. A long flowline or riser can generate pressure fluctuations which could require additional control of the wellhead pressure to minimize the impact of these fluctuations on the well.

d. Control instability in the well with the lift gas injection rate, but if necessary, exert back pressure on the tubing at the wellhead. Control instability in the flowline and riser with added points of lift gas injection at the wellhead or at the riser base.

e. If wellhead back pressure control is required, use an automated control valve with a manual back-up valve.

f. Use a fast-acting control valve as it may be necessary to dynamically control the back pressure to prevent upsets due to downstream pressure fluctuations, or upstream pressure heading.


5.1.4.3.5 Practices for Back Pressure at Manifold

a. Use wellhead control to exert back pressure upstream of the production manifold to limit the impact of pressure heading or fluctuations in the piping coming into the manifold.

b. Use an automated control valve with a manual back-up valve.

c. Use a fast-acting control valve as it may be necessary to dynamically control the back pressure to prevent upsets due to upstream pressure heading, for example in a riser.


5.1.4.4 Recommended Practices for Surveillance


5.1.4.4.1 Practices for Surveillance Strategy

a. Develop a strategy for conducting gas-lift surveillance.

b. Develop and train a staff of engineers, technicians, analysts, and operators to implement this strategy on a continuous, 24/7 basis.

c. Implement a surveillance system, using automation and data processing. See API Recommended Practice 19G12 for specific recommendations.

d. Conduct regular reviews of the strategy on at least a monthly basis. Is it being used as intended? Is it producing the desired results? Are changes needed?


5.1.4.4.2 Practices for Detecting Problems with Alarms

a. Make very wise use of alarms.

b. It is easy to generate more alarms than can be reviewed and addressed by the surveillance staff.

c. Develop alarm reports that contain meaningful, actionable information.


5.1.4.4.3 Practices for Detecting Problems with Reports

a. Make wise use of reports. Produce them only when needed, or when requested. Produce them automatically at desired times, locations.

b. Reports can be of: Current values Hourly values produced at shift change Daily valves Monthly values

c. Reports can be: By gas-lift system or well For exception cases only Totalled Sorted

d. Reports can contain: Measured data Calculated values


Modelled values Predicted values Performance indicators


5.1.4.4.4 Practices for Detecting Problems with Displays

a. Create interactive displays of each gas-lift well.

b. Make them interactive so commands can be issued from them.

c. Display pertinent measured values on the displays.

d. Display pertinent alarm information on the displays.

e. Display pertinent calculated values, such as lift gas injection depth.

f. Include links on the displays to link directly to pertinent reports, trends, or models.


5.1.4.4.5 Practices for Detecting Problems with Trends

a. Use trend plots of all measured and calculated variables vs. time.

b. Permit one or multiple variables to be plotted on the “y” axis.

c. Permit variable time scales (from minutes to months) to be plotted on the “x” axis.

d. Provide easy access to the plots from the User Interface and the Displays.

e. Permit trend plots to be automatically generated when a pertinent alarm occurs. For example, if a well becomes unstable, automatically generate a trend plot of the injection and production pressures.


5.1.4.4.6 Practices for Detecting Problems with X/Y Plots

a. Use X/Y plots to graph pertinent information.


b. For example, plot injection and production pressure vs. depth in each gas-lift well.

c. Use these plots to view and understand the likely depth of lift gas injection.


5.1.4.4.7 Practices for Detecting Problems with Models

a. Implement models of each component of the gas-lift process, including the pressure drop though the: Injection flowline Injection manifold Injection piping at the wellhead Pressure profile in the casing annulus Operating gas-lift valve or orifice Pressure profile in the tubing Production piping in the tubing head Production flowline (if pertinent) Riser (if pertinent) Production manifold Production facilities

b. Where feasible, use measured values to calibrate the models.

c. Re-calibrate the models when there is a change in the operating performance of the gas-lift system.

d. Where pertinent, use dynamic models to predict pressure and temperature performance in each component of the system under various operating conditions. See API RP 19G11 for detailed recommended practices on using dynamic models.


5.1.4.4.8 Practices for Detecting Problems with Performance Comparisons

a. Detect operating problems by comparing actual performance with predicted performance based on the calibrated models.

b. Display problems with: Pertinent alarm messages Pertinent reports Trend plots that contain both modelled and measured values..



5.1.4.4.9 Practices for Addressing Problems

a. Some problems can be addressed by using automated or manual controls. For example: Close a well wellhead injection valve if there is a problem in the

injection system Close a wellhead production valve if there is a problem in the

production system Change injection rate to work down (unload) to a deeper gas-lift

valve Change injection rate to stabilize an unstable well Change injection rate to solve icing on an injection control valve Change well test frequency or duration to obtain more accurate well

tests.

b. Other problems require manual intervention. Change gas-lift valves if they can be changed by wireline or other

retrieval mechanism Change failed or impaired components in the injection system Change failed or impaired components in the production system Change failed or impaired measurement devices Change failed or impaired control devices.

c. Still other problems require more extensive manual intervention. In some cases, workovers are needed if it is feasible to perform

workovers. If it isn’t feasible, the challenging gas-lift wells must be designed to

work perpetually, without the need to be worked over. If a well needs to be worked over, but a workover isn’t feasible,

reserves will be lost. Is that acceptable? What is the alternative?


5.1.4.4.10 Practices for Evaluating Results

a. Whenever any change is made in the operation of a gas-lift system, it must be evaluated to learn if the correct change was made, if it achieved the desired results, and if the same type of change should be tried in the future.

b. Use the monitoring and surveillance techniques recommended above to evaluate each change, and report and study the results to learn from them.


c. If a change didn’t produce the desired results, understand why, by conducting a root cause of failure analysis, and improve the process next time.


5.1.4.5 Recommended Practices for Optimization

a. It is recommended to understand what optimization is not: It is not merely making gas-lift work It is not injecting some gas and receiving some production It is not maximizing oil production, or minimizing gas injection. It is not even eliminating failures.

b. Optimization is developing and following a long-term strategy to optimize the overall economic return on investment considering all costs and incomes associated with the gas-lift operation.


5.1.4.5.1 Practices for Optimization Per Well

a. A gas-lift well is optimized when the long-term total net income from produced oil and gas, minus the total costs for equipment, services, and expendables, is maximized.

b. Total net income from produced oil and gas is equal to: Gross income from produced oil and gas, minus Royalties, minus Taxes.

c. Total costs for equipment include: Purchase and/or lease and/or replacement of equipment, plus Operating costs of equipment, plus Maintenance of equipment.

d. Total costs for services include: Staffing, plus Well servicing, plus Workover servicing.

e. Total costs for expendables include: Fuel, plus Chemicals.

f. Develop an optimization model for the well:


Determine the well’s inflow performance relationship. The recommended model is the Vogel IPR curve, unless there is evidence that a more sophisticated model is needed.

Develop the well’s gas-lift performance curve. This is plot of production rate vs. injection rate. Normally, this curve shows oil production vs. gas injection, but for true optimization, it is also necessary to model water and gas production vs. injection rate.

Determine the minimum injection rate below which the well will be unstable at the desired lift depth.

Determine the maximum injection rate above which injection will become uneconomic.

Set the limits on injection between the minimum and maximum rates and by using the performance curve.

Use the incomes and costs developed above to determine the economic optimum injection point.

Strive to operate at the optimum point unless the system optimization dictates otherwise.


5.1.4.5.2 Practices for System Optimization

a. Gas-lift wells almost never operate alone; they operate as part of a gas-lift system.

b. In a gas-lift system, there is rarely just enough gas to operate all wells at their optimum rates. Normally, there is either too little gas or too much.

c. Start by determining the gas-lift performance curve, and the minimum, maximum, and optimum injection rates for each well.

d. Develop and optimization table which contains each well in the system.

e. For each well, determine its economic production at each injection rate, starting at the highest rate and working down to the minimum rate for the well.

f. If there is more gas available than needed to produce each well at its economic optimum rate, add gas to those wells that show the largest gain with the added injection.

g. If a well reached its maximum rate and gas must still be used, use it for other wells, or use the gas in some other way such as sales or flare. Do not over-inject gas into wells as they may become unstable and both gas and energy will be wasted.

h. If there is less gas available than needed to produce each well at its economic optimum rate, remove gas from those wells that lose the least with the reduced gas.


i. If a well reaches its minimum rate and gas must still be removed from the system, stop injection into the well rather than allow it to become unstable.


5.1.5 Maintenance

Gas-lift systems employed in challenging applications must be continuously maintained to assure system integrity for safety, environmental protection, and successful economic operation.


5.1.5.1 Recommended Practices for Items to be Maintained

a. Maintenance of certain components of the gas-lift system is best performed by replacing failed or worn equipment with new equipment. In these cases, spare parts must be maintained on location.

b. Maintenance of other components must be performed on the equipment.


5.1.5.1.1 Practices for Distribution System Components

a. The distribution system consists primarily of piping, valves and pipelines. If these are correctly sized and selected, failure should rarely occur. If a piece does fail, it should be replaced.

b. More common are problems due to liquid accumulation in the piping system. If liquid accumulation occurs due to injection of un-dehydrated gas, the gas must be dehydrated to prevent the problem from becoming acerbated.

c. If liquids do enter the system they must be removed by pumping methanol or some other drying technique.

d. If liquid has entered the system, there may be corrosion. If corrosion is indicated, treat the system with corrosion inhibition chemicals.

e. If severe corrosion is indicated, use an instrumented pipeline inspection instrument to check for areas of severe corrosion. If such areas are found, replace the corroded pipe or valves to prevent a failure.



5.1.5.1.2 Practices for Gathering System Components

a. Similarly, the gathering system primarily consists of piping, valves, and pipelines

b. Here the common problems are due to deposits in the system that may include paraffin or sand

c. If paraffin is indicated, clean the system with hot oil or hot water.

d. If sand is indicated, flush the system with high pressure water.

e. If corrosion is indicated, treat the system in the same manner indicated for the distribution system.


5.1.5.1.3 Practices for Measurement Devices

a. If a measurement device fails, do not attempt to repair it. Replace it and send the failed instrument back to the supplier for analysis.

b. If a device loses calibration, re-calibrate it.

c. Have an ample number of spare measurement devices in store so a failed device can be replaced immediately with minimal downtime.

d. If it will take some time to replace a failed measurement device, have an alternative way to measure or estimate the variable that it measures.


5.1.5.1.4 Practices for Control Devices

a. If a control device fails, do not attempt to repair it. Replace it and send the failed control device back to the supplier for analysis.

b. Have an ample number of spare control devices in store so a failed device can be replaced immediately with minimal downtime.


c. If it will take some time to replace a failed control device, have an alternative way to control the variable or operate the well without controlling it.


5.1.5.1.5 Practices for Automation System Components

a. Maintain a current back-up of all automaton software and configuration parameters on at least a daily basis.

b. Maintain a current back-up of all automation system data on at least an hourly basis. If a piece of data is lost, have a mechanism to estimate the lost data.

c. If an automation system component fails, do not attempt to repair it. Replace it and send the failed component back to the supplier for analysis.

d. Have an ample number of spare automation system components in store so a failed device can be replaced immediately with minimal downtime.

e. If it will take some time to replace a failed automation system component, have an alternative way to manage the information.


5.1.5.1.6 Practices for Tubing

a. Check for tubing leaks at least once per month, using a distributed temperature system, a CO2 injection system, or some other qualified procedure.

b. It a tubing leak is detected, replace the failed tubing if feasible.

c. If replacement is not feasible, patch the leak with a tubing pack-off, if feasible.

d. If patching the leak isn’t feasible, stabilize the well with a combination of the necessary lift gas injection rate and tubing-head back-pressure control.


5.1.5.1.7 Practices for Casing


a. Check for casing leaks at least once per quarter, using a qualified procedure.

b. Evaluate the severity of the leak.

c. Closely monitor the tubing at the depth of the leak.

d. If the casing leak is severe, work over the well to repair the leak, if feasible.

e. If a workover is not feasible, if the leak is shallow such that a shallow formation may become pressure charged, close in the well and abandon it.

f. If the leak is deep enough so shallow formations aren’t at risk, it may be possible to continue to operate the well.

g. If a pressure above the Maximum Allowed Surface Pressure (MASP) is measured on the surface casing annulus, it may be possible to periodically bleed off the pressure to prevent a worsening condition.


5.1.5.1.8 Practices for Gas-lift Valves

a. If a gas-lift valve fails, do not attempt to repair it. Replace it and send the failed valve back to the supplier for analysis.

b. Have an ample number of spare valves in store so a failed valve can be replaced immediately with minimal downtime.

c. Test every replacement valve in the same way a new valve is tested.

d. If it will take some time to replace a failed valve, have an alternative way to produce the well; for example, by injecting at a different depth.


5.1.5.2 Recommended Practices for Intervention Strategy

a. Design a system that requires no intervention.

b. Intervention will likely be required at some point in the well’s lifetime.



5.1.5.2.1 Practices for Wireline / Slick line

a. Assure well trajectory is designed to accommodate wireline / slick usage.

b. Include adequate surface footprint to accommodate the wireline / slick line unit.

c. Include adequate vertical clearances as required.

d. Choose adequate line materials and strength based on the worst case pressure, temperature, and fluid environments.

e. Choose running tools, pulling tools, and kick-over tools per ISO 17078-3 / API 19G3.

f. Tools must meet functional requirements defined by ISO for new equipment.


5.1.5.2.2 Practices for Tractors

a. Contact Espen Odaland or Dave Parker of Aker, and Mike Johnson of ExxonMobil to provide these recommendations.


5.1.5.2.3 Practices for Coiled Tubing

a. Include adequate surface footprint to accommodate the coiled tubing unit.

b. Include adequate vertical clearances as required.

c. Choose adequate tubing materials and strength based on the worst case pressure, temperature, and fluid environments.

d. Choose a coiled tubing unit with adequate running / pulling capacity to accommodate worst case depths and loads.



5.1.5.2.4 Practices for Workover Rig

a. Include adequate surface footprint to accommodate the workover rig.

b. Include adequate vertical clearances as required.

c. Choose a workover rig with adequate running / pulling capacity to accommodate worst case depths and loads.

d. Choose adequate work string materials and strength based on the worst case pressure, temperature, and fluid environments.


5.1.5.2.5 Practices for Never Intervening

a. Design for single point injection.

b. Design well equipment to accommodate necessary operations including unloading, kick-off, and routine gas-lift operations.

c. Select equipment that has highest design validation and product functional testing requirements.

d. If current requirements don’t address the worst case scenarios, specify more stringent requirements.

e. Perform SIT (systems integration testing) to assure compatibility of all system components before installation.

f. Validate system performance before removing the completion rig.

g. Implement operating instructions to address all contingencies without risking downhole equipment

h. Implement training to assure engineering and operating personnel understand and can comply with operating instructions.


5.1.6 Staff

Highly skilled, trained, and motivated personnel are needed to successfully operate gas-lift systems in challenging environments.



5.1.6.1 Recommended Practices for Teams

a. At least three teams are needed for managing and operating challenging gas-lift applications. There are: Steering or system management team Engineering, automation team Surveillance team


5.1.6.1.1 Practices for System Management Team

a. Provide overall priority, justification, direction, focus.

b. Have representation from broad spectrum of stake holders in the company.

c. Chaired by member of management team. Essential to have strong management buy in

d. Gas-lift champion must facilitate. Call meetings, set agendas, “drive” the project


e. Most members should be from operating company staff.

f. Most important early in project life, but may exist over life of the project.


5.1.6.1.2 Practices for Engineering Team

a. Responsible for project execution. Define, design, build, test, implement, commission, maintain

b. Chaired by project engineer.

c. Champion serves as advisor.

d. Must function for life of project.

e. Must have members with special skills. Well design, hardware, instrumentation, controls, gas-lift equipment Well equipment installation Well equipment operation Well equipment maintenance Some members may come from 3rd parties

f. Must have members from operations, maintenance, and well analysis. They must provide input and feedback Their objectives and needs must be met


5.1.6.1.3 Practices for Operations Team

a. They must monitor, control, optimize the gas-lift operation on a daily, 24/7 basis.

b. May have a formal “core” team and many ad-hoc members.

c. The team chair may be a: Well analyst, production engineer, production technologist, well

surveillance specialist,

d. Chair must assure that: People are continuously assigned and motivated to monitor, control,

and optimize the gas-lift system They have training they need


They have support they need from other functions in company or from third parties for troubleshooting, maintenance, well servicing, system enhancements, training


5.1.6.2 Recommended Practices for Training

a. There are three levels of training required: Aware Knowledgeable Skilled.


5.1.6.2.1 Practices for Basic Training

a. There levels of basic training are required.

Aware - awareness training consists of the followingi. Attend "high level" gas-lift course or seminarii. Maintain awareness of important gas-lift issues iii. Have good understanding of:

- Relative merits of each form of gas-lift equipment- Why gas-lift has been chosen for this field


- Skills and personal characteristics needed by knowledgeable and skilled gas-lift staff

- Value of proper gas-lift system deployment, including equipment selection, design, installation, operation, optimization, troubleshooting, and surveillance

Knowledgeable - to be knowledgeable, the following training is needed:i. Attend a "high level" gas-lift course or seminarii. Attend an "intermediate level" gas-lift course that provides

thorough understanding of gas-lift equipment selection, design, installation, operation, optimization, troubleshooting, surveillance

iii. Maintain awareness of key gas-lift technologies and practices

iv. Spend time actually working in one or more facets of gas-liftv. Obtain full set of awareness that is required for "aware" levelvi. Have detailed knowledge of both technical and business

issues involved in gas-liftvii. Have ability to advise people who are directly involved in

gas-lift engineering and/or operations, by assisting them in:- Obtaining needed resources- Prioritizing their work- Evaluating economics of their projects.

Skilled - to be skilled, the following training is needed:i. Attend a "high level" gas-lift course or seminarii. Attend an "intermediate level" gas-lift course that provides

thorough understanding of gas-lift equipment selection, design, installation, operation, optimization, troubleshooting, surveillance

iii. Attend a "comprehensive" gas-lift courses that provides thorough and detailed understanding of all of the facets of gas-lift

iv. These courses should provide significant "hands on" training in performing the various aspects of gas-lift

v. Obtain the full set of "awareness" and "knowledge" that are required for the "aware" and "knowledgeable" levels of competency

vi. Maintain awareness of key gas-lift technologies and practices by continuing education - Attend company and/or industry gas-lift workshops

and/or seminars and sessions for sharing best practices

- Be fully conversant with key recommended practices produced and maintained by various sources in industry

vii. Spend time working under direct tutelage of an expert gas-lift engineer, well analyst, technician, or operator- Obtain practical, hands-on experience with each

aspect of gas-lift with which the person is involved- Receive "feedback" on activities performed, in terms of

evaluations of actual gas-lift installations


viii. Develop ability to train "new" staff in effective gas-lift engineering and/or operations


5.1.6.2.2 Practices for Training Simulators

a. Use training simulators to: Simulate all aspects of the gas-lift system and operation Use the simulators to train and quality new gas-lift staff Use the simulators before each hitch to practice and/or gain a

refresher on gas-lift monitoring, control, surveillance, problem detection and diagnosis, and root cause of failure analysis.


5.1.6.2.3 Practices for Staff Certification

a. Test all gas-lift staff to assure they have successfully passed the Aware, Knowledgeable, or Skilled level.

b. Use industry accepted qualification exams produced by the American Petroleum Institute.

c. Require all staff to be re-certified at least annually.


committee 11v/docs_api_gaslift... · web viewuse side-pocket mandrels with a pressure rating...

Documents